1. Field
The disclosed concept pertains generally to methods of detecting islanding and, more particularly, to methods of detecting islanding for an area electric power system. The disclosed concept also pertains to area electric power systems providing an anti-islanding function.
2. Background Information
In electric utility systems, a grid outage condition can cause the creation of an “island” including the electrical load and the power generation source(s). Such an island is undesirable and is of a particular concern in distributed power generation systems having a number of power generation sources and loads coexisting on a distribution feeder. For example, such an island can result in an abnormal voltage or frequency being supplied to the load. Furthermore, through back-feeding, such an island can present a safety hazard to workers for upstream power circuits.
When an inverter is electrically connected to the utility grid, it is necessary to match the inverter frequency and voltage amplitude with that of the grid. The inverter uses the grid as its reference and generates an output voltage that is synchronized with the grid. If the grid becomes disconnected, then the inverter does not see any change in frequency or voltage and will continue to supply power if the output power of the inverter matches with the local load demand on the grid. Such a condition is known as islanding, which can have substantial safety and performance implications.
In FIG. 1, when a circuit breaker (CB) 2 is open under the condition of zero current flowing into utility 4, an electrical island 6 is formed including photovoltaic (PV) inverter 8 and local load 10.
For example, islanding results in a degradation of the quality of electricity supplied to the customer (e.g., local load 10) during the islanding period due to lack of utility control. An uncontrolled frequency and/or voltage excursion can damage customer equipment. Furthermore, if grid disconnection is the result of a transient fault in the system, then interrupting devices will try to re-close the grid connection after a few cycles (e.g., typically, about 12 to 15 cycles). Re-closing can potentially damage the inverter 8 since the voltages in the island 6 are not necessarily synchronized with the grid (e.g., utility 4). When the grid is reconnected, the grid voltage can have a different phase angle with respect to the islanded voltage 12. This can cause a relatively large over-current that can damage the inverter 8, which is already in the system and islanded with the load 10.
In order to address these concerns, IEEE 1547 (Standard for Interconnecting Distributed Resources with Electric Power Systems) was developed for utility interconnection inverters. This standard was adopted by Underwriters Laboratories as UL 1741 (Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources). In addressing the islanding issue, these standards require the inverter to be able to detect the loss of the grid and disconnect within a prescribed time by employing a resonant circuit connected in parallel with the load as defined by the standards.
Referring to FIG. 2, an IEEE test (resonant) circuit 14 to verify an anti-islanding control function of a conventional grid-connected inverter 16 is shown. The test inverter 16 is electrically connected with the resonant circuit 14 including reactive components 18,20 sized at 250% (K*2.5) of the load 21 (K) in an island formed when circuit breaker or disconnect 22 is opened. The output of the inverter 16 and the reactive components 18,20 are tuned to create an island at, for example, 60 Hz when the anti-islanding control function of the inverter 16 is disabled. During the anti-islanding test, the utility end circuit breaker or disconnect 22 is opened and the time to open the inverter contactor 24 and cease powering the load 21 is timed. The inverter 16 meets IEEE 1547 if it ceases to export power within two seconds of opening the circuit breaker or disconnect 22. After the grid outage, the resonant circuit 14 will not allow the output voltage and frequency of the inverter 16 to drift. Hence, the inverter 16 must have a suitable anti-islanding control function to detect the islanding condition.
It is known that the grid has a specific impedance and by injecting a signal, which is not at grid frequency, into a grid interconnection and by looking for loss of that signal, an islanding condition can be detected. U.S. Pat. No. 6,603,290, for example, discloses detecting the occurrence of an islanding condition in the electrical connection of a distributed power generation source to an electrical power system or utility. A voltage or current signal is injected into the system, and the resulting system impedance is determined. The resulting determination is used as an indicator of the islanding condition.
IEEE 1547 does not address a common situation in recent years where there is a plurality of inverters 26,28,30 electrically connected to a utility 32 at a generation site as shown in FIG. 3. However, each of the inverters 26,28,30 can affect island detection by the other inverters, which can adversely affect operation of anti-islanding control functions and related safety.
Known conventional inverters normally operate at a power factor of 1.0 by making sure that reactive power injected into the grid is zero at all inverter output power levels. When the power factor is adjusted for unity power factor, the resonant conditions of the resonant circuit 14 (FIG. 2) are not disturbed during an islanding condition. Furthermore, since the trip time requirement of IEEE 1547 is two seconds from the time the utility is lost, the load could potentially see a relatively very poor quality power supply while the anti-islanding control function is determining the status. In other words, abnormal load conditions are not controlled.